Prior Art Background
The process of extracting oil and gas typically consists of operations that include preparation, drilling, completion, production and abandonment.
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling the wellbore is lined with a string of casing.
Open Hole Well Completions
Open hole well completions use hydraulically set mechanical external packers instead of bridge plugs and cement to isolate sections of the wellbore. These packers typically have elastomer elements that expand to seal against the wellbore and do not need to be removed, or milled out, to produce the well. Instead of perforating the casing to allow fracturing, these systems have sliding sleeve tools to create ports in between the packers. These tools can be opened hydraulically (at a specific pressure) or by dropping size-specific actuation balls into the system to shift the sleeve and expose the port. The balls create internal isolation from stage to stage, eliminating the need for bridge plugs. Open hole completions permit fracture treatments to be performed in a single, continuous pumping operation without the need for a drilling rig. Once stimulation treatment is complete, the well can be immediately flowed back and production brought on line. The packer may sustain differential pressures of 10,000 psi at temperatures up to 425° F. and set in holes enlarged up to 50%.
Ball Sleeve Operation
The stimulation sleeves have the capability to be shifted open by landing a ball on a ball seat. The operator can use several different sized dropping balls and corresponding ball-landing seats to treat different intervals. It is important to note that this type of completion must be done from the toe up with the smallest ball and seat working the bottom/lowest zone. The ball activated sliding sleeve has a shear-pinned inner sleeve that covers the fracture ports. A ball larger than the cast iron baffle in the bottom of the inner sleeve is pumped down to the seat on the baffle. A pressure differential sufficient to shear the pins holding the inner sleeve closed is reached to expose and open the fracture ports. When a ball meets its matching seat in a sliding sleeve, the pumped fluid forced against the seated ball shifts the sleeve open and aligns the ports to treat the next zone. In turn, the seated ball diverts the pumped fluid into the adjacent zone and prevents the fluid from passing to previously treated lower zones towards the toe of the casing. By dropping successively increasing sized balls to actuate corresponding sleeves, operators can accurately treat each zone up the wellbore.
The balls can be either drilled up or flowed back to surface once all the treatments are completed. The landing seats are made of a drillable material and can be drilled to give a full wellbore inner diameter. Using the stimulation sleeves with ball-activation capability removes the need for any intervention to stimulate multiple zones in a single wellbore. The description of stimulation sleeves, swelling packers and ball seats are as follows:
Stimulation Sleeve
The stimulation sleeve is designed to be run as part of the casing string. It is a tool that has communication ports between an inner diameter and an outer diameter of a wellbore casing. The stimulation sleeve is designed to give the operator the option to selectively open and close any sleeve in the casing string (up to 10,000 psi differentials at 350° F.).
Swelling Packer
The swelling packer requires no mechanical movement or manipulation to set. The technology is the rubber compound that swells when it comes into contact with any appropriate liquid hydrocarbon. The compound conforms to the outer diameter that swells up to 115% by volume of its original size.
Ball Seats
These are designed to withstand the high erosional effects of fracturing and the corrosive effects of acids. Ball seats are sized to receive/seat balls greater than the diameter of the seat while passing through balls that have a diameter less that the seat.
Because the zones are treated in stages, the lowermost sliding sleeve (toe ward end or injection end) has a ball seat for the smallest sized ball diameter size, and successively higher sleeves have larger seats for larger diameter balls. In this way, a specific sized dropped ball will pass though the seats of upper sleeves and only locate and seal at a desired seat in the well casing. Despite the effectiveness of such an assembly, practical limitations restrict the number of balls that can be run in a single well casing. Moreover, the reduced size of available balls and ball seats results in undesired low fracture flow rates.
Prior Art System Overview (0100)
As generally seen in a system diagram of FIG. 1 (0100), prior art systems associated with open hole completed oil and gas extraction may include a wellbore casing (0101) laterally drilled into a bore hole in a hydrocarbon formation. It should be noted the prior art system (0100) described herein may also be applicable to cemented wellbore casings. An annulus is formed between the wellbore casing (0101) and the bore hole.
The wellbore casing (0101) creates a plurality of isolated zones within a well and includes an port system that allows selected access to each such isolated zone.
The casing (0101) includes a tubular string carrying a plurality of packers (0110, 0111, 0112, 0113) that can be set in the annulus to create isolated fracture zones (0160, 0161, 0162, 0163). Between the packers, fracture ports opened through the inner and outer diameters of the casing (0101) in each isolated zone are positioned. The fracture ports are sequentially opened and include an associated sleeve (0130, 0131, 0132, 0133) with an associated sealable seat formed in the inner diameter of the respective sleeves. Various diameter balls (0150, 0151, 0152, 0153) could be launched to seat in their respective seats. By launching a ball, the ball can seal against the seat and pressure can be increased behind the ball to drive the sleeve along the casing (0101), such driving allows a port to open one zone. The seat in each sleeve can be formed to accept a ball of a selected diameter but to allow balls of lower diameters to pass. For example, ball (0150) can be launched to engage in a seat, which then drives a sleeve (0130) to slide and open a fracture port thereby isolating the fracture zone (0160) from downstream zones. The toe ward sliding sleeve (0130) has a ball seat for the smallest diameter sized ball (0150) and successively heel ward sleeves have larger seats for larger balls. As depicted in FIG. 1, the ball (0150) diameter is less than the ball (0151) diameter which is less than the ball (0152) diameter and so on. Therefore, limitations with respect to the inner diameter of wellbore casing (0101) may tend to limit the number of zones that may be accessed due to limitation on the size of the balls that are used. For example, if the well diameter dictates that the largest sleeve in a well casing (0101) can at most accept a 3 inch ball diameter and the smallest diameter is limited to 2 inch ball, then the well treatment string will generally be limited to approximately 8 sleeves at ⅛ inch increments and therefore can treat in only 8 fracturing stages. With 1/16th inch increments between ball diameter sizes, the number of stages is limited to 16. Limiting number of stages results in restricted access to wellbore production and the full potential of producing hydrocarbons may not be realized. Therefore, there is a need for actuating sleeves with actuating elements to provide for adequate number of fracture stages without being limited by the size of the actuating elements (restriction plug elements), size of the sleeves, or the size of the wellbore casing.
Prior Art Method Overview (0200)
As generally seen in the method of FIG. 2 (0200), prior art associated with oil and gas extraction includes site preparation and installation of a bore hole in step (0201). In step (0202) preset sleeves may be fitted as an integral part of the wellbore casing (0101) that is installed in the wellbore. The sleeves may be positioned to close each of the fracture ports disallowing access to hydrocarbon formation. After setting the packers (0110, 0111, 0112, 0113) in step (0202), sliding sleeves are actuated by balls to open fracture ports in step (0203) to enable fluid communication between the well casing and the hydrocarbon formation. The sleeves are actuated in a direction from upstream to downstream. Prior art methods do not provide for actuating sleeves in a direction from downstream to upstream. In step (0204), hydraulic fracturing fluid is pumped through the fracture ports at high pressures. The steps comprise launching an actuating ball, engaging in a ball seat, opening a fracture port (0203), isolating a hydraulic fracturing zone, and hydraulic fracturing fluids into the perforations (0204), are repeated until all hydraulic fracturing zones in the wellbore casing are fractured and processed. The fluid pumped into the fracture zones at high pressure remains in the connected regions. The pressure in the connected region (stored energy) is diffused over time. Prior art methods do not provide for utilizing the stored energy in a connected region for useful work such as actuating sleeves. In step (0205), if all hydraulic fracturing zones are processed, all the actuating balls are pumped out or removed from the wellbore casing (0206). A complicated ball counting mechanism may be employed to count the number of balls removed. In step (0207) hydrocarbon is produced by pumping from the hydraulic fracturing stages.
Step (0203) requires that a right sized diameter actuating ball be deployed to seat in the corresponding sized ball seat to actuate the sliding sleeve. Progressively increasing diameter balls are deployed to seat in their respectively sized ball seats and actuating the sliding sleeves. Progressively sized balls limit the number stages in the wellbore casing. Therefore, there is a need for actuating sleeves with actuating elements to provide for adequate number of fracture stages without being limited by the size of the actuating elements, size of the sleeves, or the size of the wellbore casing. Moreover, counting systems use all the same size balls and actuate a sleeve on an “nth” ball. For example, counting systems may count the number of balls dropped balls as 10 before actuating on the 10th ball.
Furthermore, in step (0203), if an incorrect sized ball is deployed in error, all hydraulic fracturing zones toe ward (injection end) of the ball position may be untreated unless the ball is retrieved and a correct sized ball is deployed again. Therefore, there is a need to deploy actuating seats with constant inner diameter to actuate sleeves with actuating elements just before a hydraulic fracturing operation is performed. Moreover, there is a need to perform out of order hydraulic fracturing operations in hydraulic fracturing zones.
Additionally, in step (0206), a complicated counting mechanism is implemented to make certain that all the balls are retrieved prior to producing hydrocarbon. Therefore, there is a need to use degradable actuating elements that could be flown out of the wellbore casing or flown back prior to the surface prior to producing hydrocarbons.
Additionally, in step (0207), smaller diameter seats and sleeves towards the toe end of the wellbore casing might restrict fluid flow during production. Therefore, there is need for larger inner diameter actuating seats and sliding sleeves to allow unrestricted well production fluid flow. Prior to production, all the sleeves and balls need to be milled out in a separate step.
Deficiencies in the Prior Art
The prior art as detailed above suffers from the following deficiencies:                Prior art systems do not provide for actuating sleeves with actuating elements to provide for adequate number of fracture stages without being limited by the size of the actuating elements, size of the sleeves, or the size of the wellbore casing.        Prior art systems such as coil tubing may be used to open and close sleeves, but the process is expensive.        Prior art methods counting mechanism to count the balls dropped into the casing is not accurate.        Prior art systems do not provide for a positive indication of an actuation of a downhole tool.        Prior art methods do not provide for determining the location of a downhole tool.        Prior art systems do not provide for performing out of order hydraulic fracturing operations in hydraulic fracturing zones.        Prior art systems do not provide for using degradable actuating elements that could be flown out of the wellbore casing or flown back prior to the surface prior to producing hydrocarbons.        Prior art systems do not provide for setting constant diameter larger inner diameter sliding sleeves to allow unrestricted well production fluid flow.        Prior art methods do not provide for actuating sleeves in a direction from downstream to upstream.        Prior art methods do not provide for utilizing the stored energy in a connected region for useful work.        Prior art apparatus do not provide for actuating devices in downhole tools with reverse flow.        
While some of the prior art may teach some solutions to several of these problems, the core issue of utilizing stored energy in a connected region for useful work has not been addressed by prior art.